Cable injector for deploying artificial lift system

ABSTRACT

An injector for deploying a cable into a wellbore includes a traction assembly having at least a stationary segment and a movable segment. Each segment includes: a drive sprocket; an idler sprocket; a track looped around and between the sprockets; a set of grippers fastened to and disposed along the respective track, and a frame. The frame: is connected to the stationary segment, has a coupling for connection to a pressure control assembly (PCA), and has a passage for receiving the cable. The injector further includes a motor torsionally connected to the drive sprocket of the stationary segment.

BACKGROUND OF THE DISCLOSURE

1. Field of the Disclosure

Embodiments of the present disclosure generally relate to a cableinjector for deploying an artificial lift system.

2. Description of the Related Art

The oil industry has utilized electric submersible pumps (ESPs) toproduce high flow-rate wells for decades, the materials and design ofthese pumps has increased the ability of the system to survive forlonger periods of time without intervention. These systems are typicallydeployed on the tubing string with the power cable fastened to thetubing by mechanical devices such as metal bands or metal cableprotectors. Well intervention to replace the equipment requires theoperator to pull the tubing string and power cable requiring a wellservicing rig and special spooler to spool the cable safely. Theindustry has tried to find viable alternatives to this deployment methodespecially in offshore and remote locations where the cost increasessignificantly. There has been limited deployment of cable inserted incoil tubing where the coiled tubing is utilized to support the weight ofthe equipment and cable. Although this system is seen as an improvementover jointed tubing, the cost, reliability and availability of coiledtubing units have prohibited use on a broader basis.

SUMMARY OF THE DISCLOSURE

Embodiments of the present disclosure generally relate to a cableinjector for deploying an artificial lift system. In one embodiment, aninjector for deploying a cable into a wellbore includes a tractionassembly having at least a stationary segment and a movable segment.Each segment includes: a drive sprocket; an idler sprocket; a tracklooped around and between the sprockets; a set of grippers fastened toand disposed along the respective track, and a frame. The frame: isconnected to the stationary segment, has a coupling for connection to apressure control assembly (PCA), and has a passage for receiving thecable. The injector further includes a motor torsionally connected tothe drive sprocket of the stationary segment.

In another embodiment, a method of deploying a downhole tool into awellbore includes: connecting the downhole tool to a cable; lowering thedownhole tool into a pressure control assembly (PCA) and wellheadadjacent to the wellbore using the cable; after lowering the downholetool, connecting a cable injector to the PCA and closing the cableinjector around the cable; and operating the cable injector, therebyinjecting the cable into the wellbore and lowering the downhole tool toa deployment depth in the wellbore.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the presentdisclosure can be understood in detail, a more particular description ofthe disclosure, briefly summarized above, may be had by reference toembodiments, some of which are illustrated in the appended drawings. Itis to be noted, however, that the appended drawings illustrate onlytypical embodiments of this disclosure and are therefore not to beconsidered limiting of its scope, for the disclosure may admit to otherequally effective embodiments.

FIG. 1A illustrates a launch and recovery system (LARS) at a wellsitefor deploying an artificial lift system (ALS), according to oneembodiment of the present disclosure. FIG. 1B illustrates a power cableof the ALS. FIGS. 1C and 1D illustrate a wireline of the ALS.

FIGS. 2A-2D illustrate an electric submersible pump (ESP) of the ALS.

FIGS. 3A, 3C, and 3D illustrate a cable injector of the LARS in an openor partially open position. FIG. 3B illustrates the cable injector in aclosed position.

FIGS. 4A and 4B illustrate insertion of the ESP into a wellbore usingthe LARS. FIG. 4C illustrates operation of the ESP.

FIG. 5A illustrates a lubricator and the cable injector connectedthereto for use with the LARS, according to another embodiment of thepresent disclosure. FIG. 5B illustrates an alternative pressure controlassembly (PCA) for use with the LARS, according to another embodiment ofthe present disclosure.

FIG. 6A illustrates a power cable deployed ESP for use with a modifiedLARS. FIG. 6B illustrates insertion of the power cable deployed ESP intothe wellbore using the cable injector, according to another embodimentof the present disclosure. FIG. 6C illustrates operation of the powercable deployed ESP.

FIGS. 7A-7D illustrate insertion of the power cable deployed ESP intothe wellbore using the cable injector, according to another embodimentof the present disclosure. FIG. 7E illustrates operation of the powercable deployed ESP.

FIG. 8A illustrates an alternative cable injector for the LARS. FIG. 8Billustrates a portion of another alternative cable injector for theLARS.

DETAILED DESCRIPTION

FIG. 1A illustrates a launch and recovery system (LARS) 1 at a wellsitefor deploying an artificial lift system (ALS), according to oneembodiment of the present disclosure. The LARS 1 may include a wireleinetruck 40, a pressure control assembly (PCA), such as one or more (twoshown) blowout preventers (BOPs) 38, one or more running tools 59 (FIG.4A), and a cable injector 100 (FIG. 3A).

A wellbore 5 w has been drilled from a surface 5 s of the earth into ahydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir 6(FIG. 4A). A string of casing 10 c has been run into the wellbore 5 wand set therein with cement (not shown). The casing 10 c has beenperforated 9 (FIG. 4B) to provide to provide fluid communication betweenthe reservoir 6 and a bore of the casing 10 c. A wellhead 10 h has beenmounted on an end of the casing string 10 c. A string of productiontubing 10 p extends from the wellhead 10 h to the reservoir 6 totransport production fluid 7 (FIG. 4C) from the reservoir 6 to thesurface 5 s. A packer 8 (FIG. 4A) has been set between the productiontubing 10 p and the casing 10 c to isolate an annulus 10 a (FIG. 4B)formed between the production tubing and the casing from productionfluid 7.

A production (aka Christmas) tree 30 has been installed on the wellhead10 h. The production tree 30 may include a master valve 31, tee 32, aswab valve 33, a cap 34 (FIG. 4C), and a production choke 35. Productionfluid 7 from the reservoir 6 may enter a bore of the production tubing10 p, travel through the tubing bore to the surface 5 s. The productionfluid 7 may continue through the master valve 31, the tee 32, andthrough the choke 35 to a flow line (not shown). The production fluid 7may continue through the flow line to a separation, treatment, andstorage facility (not shown). The reservoir 6 may initially be naturallyproducing and may deplete over time to require an artificial lift system(ALS) to maintain production. The ALS may include a control unit 39(FIG. 4C) located at the surface 5 s, a power cable 20, and a downholeassembly, such as an electrical submersible pump (ESP) 60 (FIGS. 2A-2D).Alternatively, the downhole assembly may include an electricalsubmersible compressor. In anticipation of depletion, the productiontubing string 10 p may have been installed with a dock 15 (FIG. 4A)assembled as a part thereof and the power cable 20 secured therealong.

The dock 15 may receive a lander 65 (FIG. 2A) of the ESP 60 and includea subsurface safety valve (SSV) 3, one or more sensors 4 u,b, a part,such as one or more followers 13, of an auto-orienter, a penetrator 14,a part, such as one or more boxes 16, of a wet matable connector, apolished bore receptacle (PBR) 17, and a torque profile. The SSV 3 mayinclude a housing, a valve member, a biasing member, and an actuator.The valve member may be a flapper operable between an open position anda closed position. The flapper may allow flow through thehousing/production tubing bore in the open position and seal thehousing/production tubing bore in the closed position. The flapper mayoperate as a check valve in the closed position i.e., preventing flowfrom the reservoir 6 to the wellhead 10 h but allowing flow from thewellhead to the reservoir. Alternatively, the SSV 3 may bebidirectional. The actuator may be hydraulic and include a flow tube forengaging the flapper and forcing the flapper to the open position. Theflow tube may also be a piston in communication with a hydraulic conduitof a control line 11 extending along an outer surface of the productiontubing 10 p to the wellhead 10 h. Injection of hydraulic fluid into thehydraulic conduit may move the flow tube against the biasing member(i.e., spring), thereby opening the flapper. The SSV 3 may also includea spring biasing the flapper toward the closed position. Relief ofhydraulic pressure from the conduit may allow the springs to close theflapper.

Each sensor 4 u,b may be a pressure or pressure and temperature (PT)sensor. The sensors 4 u,b may be located along the production tubing 10p so that the upper sensor 4 u is in fluid communication with an outletof the ESP 60 and a lower sensor 4 b is in fluid communication with aninlet 80 (FIG. 2C) of the ESP 60. The sensors 4 u,b may be in datacommunication with a motor controller (not shown) of the control unit 39via a data conduit of the control line 11, such as an electrical oroptical cable. The data conduit may also provide power for the sensors 4u,b.

The penetrator 14 may receive an end of the cable 20. The cable 20 maybe fastened along an outer surface of the production tubing 10 p atregular intervals, such as by clamps or bands (not shown). The wetmatable connector 16, 66 may include a pair of pins 66 (FIG. 2A) andboxes 16 for each conductor 21 (FIG. 1B, three shown) of the cable 20. Asuitable wet matable connector is discussed and illustrated U.S. Pat.Pub. No. 2011/0024104, which is herein incorporated by reference in itsentirety.

The auto-orienter 13, 69 may include a cam 69 (FIG. 2A) and one or morefollowers 13. As the ESP 60 is lowered into the dock 15, theauto-orienter 13, 69 may rotate the ESP to align the pins 66 with therespective boxes 13. Each of the lander 65 and dock 15 may furtherinclude a torque profile, such one or more splines 67 (FIG. 2A), 18.Engagement of the splines 67, 18 may torsionally connect the ESP 60 tothe production tubing 10 p. A landing shoulder may be formed at a top ofeach of the splines 18 to longitudinally support the ESP 60 in theproduction tubing 10 p.

The reservoir 6 may be live and shut-in by the closed master valve 31,swab valve 33, and SSV 3. Alternatively, the reservoir 6 may be dead dueto depletion and/or by kill fluid. Alternatively, the LARS 1 may furtherinclude a lubricator 200 (FIG. 5A) for deploying the ESP 60.Alternatively, if the dock 15, power cable 20, and control line 11 wasnot installed with the production tubing 10 p, a workover rig (notshown) may be used to remove the production tubing, install the dock,power cable, and control line, and reinstall the production tubing. TheLARS 1 may then not be needed for the initial installation of the ESP 60but may be used for later servicing of the ESP.

The wireline truck 40 may be deployed to the wellsite. One or moredelivery trucks (not shown) may transport the BOPs 38, ESP 60, andrunning tool 59 to the wellsite. The wireline truck 40 may be used toremove the cap 34 from the tree 30 and install the BOPs 38 onto thetree. The wireline truck 40 may include a control room 42, a generator(not shown), a frame 44, a power converter 45, a winch 47 having adeployment cable, such as wireline 50, wrapped therearound, and a boom48. Alternatively, the deployment cable may be slickline or wire rope.The control room 42 may include a control console 42 c and aprogrammable logic controller (PLC) 42 p. The generator may bediesel-powered and may supply a one or more phase (i.e., three)alternating current (AC) power signal to the power converter 45.Alternatively, the generator may produce a direct current (DC) powersignal. The power converter 45 may include a one or more (i.e., three)phase transformer for stepping the voltage of the AC power signalsupplied by the generator from a low voltage signal to an ultra lowvoltage signal. The power converter 45 may further include a one or more(i.e., three) phase rectifier for converting the ultra low voltage ACsignal supplied by the transformer to an ultra low voltage directcurrent (DC) power signal. The rectifier may supply the ultra lowvoltage DC power signal to the wireline 50 for transmission to therunning tool 59.

The rectifier may be in electrical communication with the wireline 50via an electrical coupling (not shown), such as brushes or slip rings,to allow power and data transmission through the wireline while thewinch 47 winds and unwinds the wireline. The control console 42 c mayinclude one or more input devices, such as a keyboard and mouse ortrackpad, and one or more video monitors. Alternatively, a touchscreenmay be used instead of the monitor and input devices.

The boom 48 may be an A-frame pivoted to the frame 44 and the wirelinetruck 40 may further include a boom hoist (not shown) having a pair ofpiston and cylinder assemblies. Each piston and cylinder assembly may bepivoted to each beam of the boom and a respective column of the frame.The wireline truck 40 may further include a hydraulic power unit (HPU)46. The HPU 46 may include a hydraulic fluid reservoir, a hydraulicpump, an accumulator, and one or more control valves for selectivelyproviding fluid communication between the reservoir, the accumulator,and the piston and cylinder assemblies. The hydraulic pump may be drivenby an electric motor. The winch 47 may include a drum having thewireline 50 wrapped therearound and a motor for rotating the drum towind and unwind the wireline. The winch motor may be electric orhydraulic. A sheave may hang from the boom 48. The wireline 50 mayextend through the sheave and an end of the wireline may be fastened toa cablehead of the running tool 59. The HPU 46 may also be connected tothe BOPs 38.

The BOPs 38 may include a housing having a connector, such as a flange,formed at each longitudinal end thereof. A lower of the BOP flanges maybe connected to an upper flange of the swab valve 33 by fasteners (notshown), such as bolts or studs and nuts. The BOPs housing may have abore therethrough corresponding to a bore of the production tubing 10 p.The BOPs 38 may include one or more ram preventers, such as a blind rampreventer and a cable ram preventer. The blind ram preventer may becapable of cutting the wireline 50 when actuated and sealing the bore.The cable preventer may be capable of sealing against an outer surfaceof the wireline 50 when actuated.

FIG. 1B illustrates the power cable 20. The cable 20 may include a core27 having one or more (three shown) wires 25 and a jacket 26, and one ormore layers 29 i,o of armor. Each wire 25 may include a conductor 21, ajacket 22, a sheath 23, and bedding 24. The conductors 21 may each bemade from an electrically conductive material, such as aluminum, copper,or alloys thereof. The conductors 21 may each be solid or stranded. Eachjacket 22 may electrically isolate a respective conductor 21 and be madefrom a dielectric material, such as a polymer (i.e., ethylene propylenediene monomer (EPDM)). Each sheath 23 may be made from lubricativematerial, such as polytetrafluoroethylene (PTFE) or lead, and may betape helically wound around a respective wire jacket 22. Each bedding 24may serve to protect and retain the respective sheath 23 duringmanufacture and may be made from a polymer, such as nylon. The corejacket 26 may protect and bind the wires 25 and be made from a polymer,such as EPDM or nitrile rubber.

The armor 29 i,o may be made from one or more layers 29 i,o of highstrength material (i.e., tensile strength greater than or equal to onehundred, one fifty, or two hundred kpsi). The high strength material maybe a metal or alloy and corrosion resistant, such as galvanized steel,aluminum, or a polymer, such as a para-aramid fiber. The armor 29 i,omay include two contra-helically wound layers 29 i,o of wire, fiber, orstrip. Additionally, a buffer (not shown) may be disposed between thearmor layers 29 i,o. The buffer may be tape and may be made from thelubricative material. Additionally, the cable 20 may further include apressure containment layer 28 made from a material having sufficientstrength to contain radial thermal expansion of the core 27 and wound toallow longitudinal expansion thereof. Alternatively, the power cable 20may be flat.

FIGS. 1C and 1D illustrate the wireline 50. The wireline 50 may includean inner core 51, an inner jacket 52, a shield 53, an outer jacket 56,and one or more layers 57 i,o of armor. The inner core 51 may be thefirst conductor and made from an electrically conductive material, suchas aluminum, copper, or alloys thereof. The inner core 51 may be solidor stranded. The inner jacket 52 may electrically isolate the core 51from the shield 53 and be made from a dielectric material, such as apolymer (i.e., polyethylene). The shield 53 may serve as the secondconductor and be made from the electrically conductive material. Theshield 53 may be tubular, braided, or a foil covered by a braid. Theouter jacket 56 may electrically isolate the shield 53 from the armor 57i,o and be made from a fluid-resistant dielectric material, such aspolyethylene or polyurethane. The armor 57 i,o may be made from one ormore layers 57 i,o of the high strength material to support the ESP 60.The armor 57 i,o may include two contra-helically wound layers 57 i,o ofwire, fiber, or strip.

Additionally, the wireline 50 may include a sheath 55 disposed betweenthe shield 53 and the outer jacket 56. The sheath 55 may be made fromlubricative material, such as polytetrafluoroethylene (PTFE) or lead,and may be tape helically wound around the shield 53. If lead is usedfor the sheath 55, a layer of bedding 54 may insulate the shield 53 fromthe sheath and be made from the dielectric material. Additionally, abuffer 58 may be disposed between the armor layers 57 i,o. The buffer 58may be tape and may be made from the lubricative material.

FIGS. 2A-2D illustrate the ESP 60. The ESP 60 may include the lander 65,an electric motor 70, a shaft seal 75, the inlet 80, a pump having oneor more sections 85, 95, and a packoff 99. Housings 70 h-95 h of each ofthe ESP components may be longitudinally and torsionally connected, suchas by flanged connections 61, 90 u,b. Alternatively, the flangedconnections 90 u,b may be replaced by the flanged connections 61. Shafts70 s-95 s of the motor 70, shaft seal 75, inlet 80, and pump sections85, 95 may be torsionally connected, such as by shaft couplings 63.Alternatively, the housings 70 h-95 h may be connected by threadedconnections.

The motor 70 may be filled with a dielectric, thermally conductiveliquid lubricant, such as motor oil. The motor 70 may be cooled bythermal communication with the production fluid 7. The motor 70 mayinclude a thrust bearing (not shown) for supporting the drive shaft 70s. In operation, the motor 70 may rotate the drive shaft 70 s, therebydriving the pump shafts 85 s, 95 s of the pump 85, 95. The drive shaft70 s may be directly drive the pump shaft 85 s, 95 s (no gearbox).

The motor 70 may be an induction motor, a switched reluctance motor(SRM) or a permanent magnet motor, such as a brushless DC motor (BLDC).Additionally, the ESP 60 may include a second (or more) motor for tandemoperation with the motor 70. The induction motor may be a two-pole,three-phase, squirrel-cage induction type and may run at a nominal speedof thirty-five hundred rpm at sixty Hz. The SRM motor may include amulti-lobed rotor made from a magnetic material and a multi-lobedstator. Each lobe of the stator may be wound and opposing lobes may beconnected in series to define each phase. For example, the SRM motor maybe three-phase (six stator lobes) and include a four-lobed rotor. TheBLDC motor may be two pole and three phase. The BLDC motor may includethe stator having the three phase winding, a permanent magnet rotor, anda rotor position sensor. The permanent magnet rotor may be made of oneor more rare earth, ceramic, or ceramic-metallic composite (aka cermet)magnets. The rotor position sensor may be a Hall-effect sensor, a rotaryencoder, or sensorless (i.e., measurement of back EMF in undriven coilsby the motor controller).

The shaft seal 75 may isolate the reservoir fluid 7 being pumped throughthe pump 85, 95 from the lubricant in the motor 70 by equalizing thelubricant pressure with the pressure of the reservoir fluid 7. The shaftseal 75 may house a thrust bearing (not shown) capable of supportingthrust load from the pump 85, 95. The shaft seal 75 may be positive typeor labyrinth type. The positive type may include an elastic,fluid-barrier bag to allow for thermal expansion of the motor lubricantduring operation. The labyrinth type may include tube paths extendingbetween a lubricant chamber and a reservoir fluid chamber providinglimited fluid communication between the chambers.

The pump inlet 80 may be standard type, static gas separator type, orrotary gas separator type depending on the gas to oil ratio (GOR) of theproduction fluid 7. The standard type inlet may include a plurality ofports 81 allowing reservoir fluid 7 to enter a lower or first section 85of the pump 85, 95. The standard inlet may include a screen (not shown)to filter particulates from the reservoir fluid 7. The static gasseparator type may include a reverse-flow path to separate a gas portionof the reservoir fluid 7 from a liquid portion of the reservoir fluid.

The packoff 99 may have one or more fixed seals received by the polishedbore receptacle 17 of the dock 15, thereby isolating discharge ports(not shown) of the packoff 99 from the pump inlet 80. The packoff 99 mayfurther include a latch (not shown) operable to engage a latch profile(not shown) of the dock 15, thereby longitudinally connecting the ESP 60to the production tubing 10 p. The packoff 99 may further include aninner profile for engagement with the running tool 59. Additionally, thepackoff 99 may include a bypass vent (not shown) for releasing gasseparated by the pump inlet 80 that may collect below the packoff andpreventing gas lock of the pump 85, 95. A pressure relief valve (notshown) may be disposed in the bypass vent.

The pump 85, 95 may be centrifugal or positive displacement. Thecentrifugal pump may be a radial flow or mixed axial/radial flow. Thepositive displacement pump may be progressive cavity. Each section 85,95 of the centrifugal pump may include one or more stages, each stagehaving an impeller and a diffuser. The impeller may be torsionally andlongitudinally connected to the respective pump shaft 85 s, 95 s, suchas by a key. The diffuser may be longitudinally and torsionallyconnected to a housing of the pump, such as by compression between ahead and base screwed into the housing. Rotation of the impeller mayimpart velocity to the reservoir fluid 7 and flow through the stationarydiffuser may convert a portion of the velocity into pressure. The pump85, 95 may deliver the pressurized reservoir fluid 7 to the packoffbore.

Alternatively, the pump 85, 95 may include one or more sections of ahigh speed compact pump discussed and illustrated at FIGS. 1C and 1D ofU.S. patent application Ser. No. 12/794,547, filed Jun. 4, 2010, whichis herein incorporated by reference in its entirety. High speed may begreater than or equal to ten thousand, fifteen thousand, or twentythousand revolutions per minute (RPM). Each compact pump section mayinclude one or more stages, such as three. Each stage may include ahousing, a mandrel, and an annular passage formed between the housingand the mandrel. The mandrel may be disposed in the housing. The mandrelmay include a rotor, one or more helicoidal rotor vanes, a diffuser, andone or more diffuser vanes. The rotor may include a shaft portion and animpeller portion. The rotor may be supported from the diffuser forrotation relative to the diffuser and the housing by a hydrodynamicradial bearing formed between an inner surface of the diffuser and anouter surface of the shaft portion. The rotor vanes may interweave toform a pumping cavity therebetween. A pitch of the pumping cavity mayincrease from an inlet of the stage to an outlet of the stage. The rotormay be longitudinally and torsionally connected to the motor drive shaftand be rotated by operation of the motor. As the rotor is rotated, theproduction fluid 7 may be pumped along the cavity from the inlet towardthe outlet. The annular passage may have a nozzle portion, a throatportion, and a diffuser portion from the inlet to the outlet of eachstage, thereby forming a Venturi.

Additionally, the ESP 60 may further include a sensor sub (not shown).The sensor sub may be employed in addition to or instead of the sensors4 u,b. The sensor sub may include a controller, a modem, a diplexer, andone or more sensors (not shown) distributed throughout the ESP 60. Thecontroller may transmit data from the sensors to the motor controllervia conductors 21 of the cable 20. Alternatively, the cable 20 mayfurther include a data conduit, such as data wires or optical fiber, fortransmitting the data. A PT sensor may be in fluid communication withthe reservoir fluid 7 entering the pump inlet 80. A GOR sensor may alsobe in fluid communication with the reservoir fluid 7 entering the pumpinlet 80. A second PT sensor may be in fluid communication with thereservoir fluid 7 discharged from the pump outlet/ports. A temperaturesensor (or PT sensor) may be in fluid communication with the lubricantto ensure that the motor 70 is being sufficiently cooled. A voltagemeter and current (VAMP) sensor may be in electrical communication withthe cable 20 to monitor power loss from the cable. Further, one or morevibration sensors may monitor operation of the motor 70, the pump 85,95, and/or the shaft seal 75. A flow meter may be in fluid communicationwith the pump outlet for monitoring a flow rate of the pump 85, 95.Alternatively, the tree 30 may include a flow meter (not shown) formeasuring a flow rate of the pump 85, 95 and the tree flow meter may bein data communication with the motor controller.

The control unit 39 may include a power source, such as a generator ortransmission lines, and a motor controller for receiving an input powersignal from the power source and outputting a power signal to the motor70 via the power cable and the connector 105. For the induction motor,the motor controller may be a switchboard (i.e., logic circuit) forsimple control of the motor 70 at a nominal speed or a variable speeddrive (VSD) for complex control of the motor. The VSD controller mayinclude a microprocessor for varying the motor speed to achieve anoptimum for the given conditions. The VSD may also gradually or softstart the motor, thereby reducing start-up strain on the shaft and thepower supply and minimizing impact of adverse well conditions.

For the SRM or BLDC motors, the motor controller may sequentially switchphases of the motor, thereby supplying an output signal to drive thephases of the motor 70. The output signal may be stepped, trapezoidal,or sinusoidal. The BLDC motor controller may be in communication withthe rotor position sensor and include a bank of transistors orthyristors and a chopper drive for complex control (i.e., variable speeddrive and/or soft start capability). The SRM motor controller mayinclude a logic circuit for simple control (i.e. predetermined speed) ora microprocessor for complex control (i.e., variable speed drive and/orsoft start capability). The SRM motor controller may use one ortwo-phase excitation, be unipolar or bi-polar, and control the speed ofthe motor by controlling the switching frequency. The SRM motorcontroller may include an asymmetric bridge or half-bridge.

FIGS. 3A, 3C, and 3D illustrate the cable injector 100 in an open orpartially open position. FIG. 3B illustrates the cable injector 100 in aclosed position. The cable injector 100 may include a traction assembly101, a drive motor 102, and a frame 103. The traction assembly 101 mayinclude one or more segments, such as a stationary segment 101 d and amovable segment 101 p. The stationary segment 101 d may be connected toa base 103 b of the frame 103, such as by one or more fasteners (notshown). The frame 103 may further include a coupling, such as a flange103 f, connected to the base 103 b, such as by one or more fasteners ora weld. The flange 103 f may mate with a corresponding upper flange ofthe BOPs 38 and be connected thereto by one or more fasteners.Alternatively, the coupling may be threaded or quick-connect. The frame103 may further have a passage, such a slit 115 formed through walls ofthe flange 103 f and base 103 b for receiving the wireline 50.

Each segment 101 d,p may include a respective: body 105 d,p, conveyor106 d,p, tensioner 107 p (stationary tensioner not shown), and counterbearing 116 d,p. Each body 105 d,p may be rectangular and have a cavityformed therein. Each body 105 d,p may have an open inner face foroperation of the respective conveyor 106 d,p and open upper and lowerends for assembly thereof. The upper and lower ends may be closed withend caps (not shown). Each body 105 d,p may have a respective coupling,such as a hinge knuckle 117 p,d, formed at each inner end thereof. Themovable segment 101 p may initially be connected to the stationarysegment 101 d, such as pivoted, by meshing a first mating pair of theknuckles 117 p,d and inserting a hinge pin 104 a through the meshedfirst pair such that the movable segment may swing between the open andclosed positions. The movable segment 101 p may then be closed bymeshing a second mating pair of the knuckles 117 p,d and inserting alatch pin 104 b through the meshed second pair. The open position may beutilized for receiving the wireline 50 and the closed position may beutilized for lowering and/or driving the wireline into the wellbore 5 w.

Each conveyor 106 d,p may include a respective: track, such as a belt108 d,p, gear 109 d,p, idler sprocket 110 d,p, drive sprocket 111 d,p,idler hub (not shown), drive hub 112 d,p, and set 113 d,p of grippers113. Alternatively, the tracks may be roller chains. Each gripper 113may be fastened to the respective belt 108 d,p, such as by one or morefasteners (not shown) extending through respective holes (not shown)formed through the belt. Each hole may be counter bored or counter sunksuch that the fastener head is flush or sub-flush with an underside ofthe belt. Each set 113 d,p may include grippers 113 spaced along anoutside of the respective belt 108 d,p at regular intervals. Eachgripper 113 may be made from an abrasion resistant material, such as ametal, alloy, or cermet. Each gripper 313 may have an upper portion, amid portion, and a lower portion. The mid portion of each gripper 113may have a central recess for receiving the wireline 50 and wingsextending transversely from the recess. The wings may form a bearingsurface for mating with wings of an opposed gripper during operation ofthe cable injector 100. The upper and lower portions of each gripper 113may taper toward the belt going away from the mid portion. A nominalwidth of each recess may correspond to a diameter of the wireline 50.

Each set 113 d,p of grippers 113 may engage a fraction of an outersurface of the wireline 50. In the illustrated case of two sets 113 d,p,each set may engage one-half of the wireline outer surface.Alternatively, the traction assembly 101 may include a second (or more)movable segment, such as a stationary segment and two moveable segments(FIG. 8B) or a stationary segment and three moveable segments. In thealternative having two movable segments, each set of grippers may engageone-third of the wireline outer surface and in the alternative havingthree movable segments, each set may engage one-fourth of the wirelineouter surface.

Teeth may be formed in the recess for gripping the wireline 50.Alternatively, a die having the teeth may be fastened to the gripper113. The teeth may be circumferential and decrease the nominal width ofthe recess to be less than the wireline diameter such that the teeth maypenetrate the outer armor 57 o. A receiver opening may also be formedthrough each central portion for receiving a cog 114 p,d of therespective sprockets 110 p,d, 111 p,d. A corresponding passage may beformed through the belt adjacent each receiver opening for passage ofthe cog 114 p,d therethrough. A length of each gripper and the intervalbetween adjacent grippers may correspond to a pitch of the respectivesprockets 110 p,d, 111 p,d. Each receiver opening may be shaped to meshwith the cog 114 p,d such that the gripper 113 (and belt) seats onto theadjacent bottom lands of the sprocket 110 p,d, 111 p,d, therebytransmitting driving torque/force directly from the cog to the gripper113. The gripper 113 may then transmit the driving force to therespective belt 108 d,p via the fasteners.

Each belt 108 d,p may be endless and loop around and between therespective sprockets 110 p,d, 111 p,d. Each belt 108 d,p may have a flator trapezoidal cross-section. Each belt 108 d,p may include an innercarcass made from one or more plies bonded together using an adhesiveand an outer cover encapsulating the carcass. The plies may each be madefrom natural or synthetic fibers, such as polymer, metal/alloy, ceramic,or carbon. The cover may be made from a flexible material, such as anelastomer, thermoplastic elastomer, or other suitable polymer. Each belt108 d,p may have a length sufficient to distribute clamping force alongthe wireline 50 such that a clamping pressure does not crush thewireline. The gripper teeth and belt length may also be configured suchthat the teeth do not damage the outer armor layer 57 o.

Each hub 112 d,p may be mounted to the respective body 105 d,p bybearings (not shown) such that the hub may rotate relative to the bodywhile being longitudinally and transversely supported by the body. Eachsprocket 110 p,d, 111 p,d may be disposed on a respective hub 112 d,pand torsionally connected thereto, such as by interference fit orfastener. Each gear 109 d,p may be disposed on a respective drive hub112 d,p and torsionally connected thereto, such as by interference fitor fastener. The stationary drive hub 112 d may also have a shaftcoupling (not shown) for receiving a shaft coupling (not shown) of adrive shaft 102 d of the motor 102, thereby torsionally connecting thedrive hub to the drive shaft. The gears 109 d,p may be configured tomesh upon closing of the cable injector 100, thereby torsionallyconnecting the stationary drive hub 112 d to the movable drive hub 112p.

The drive motor 102 may be hydraulic and bidirectional such that thecable injector 100 may be used to push the wireline 50 into the wellbore5 w and pull the wireline from the wellbore. The drive motor 102 mayhave a housing 102 h connected to a bracket 103 t of the frame 103, suchas by one or more fasteners (not shown). An inlet and outlet of thedrive motor may be in fluid communication with the HPU 46 via flexibleconduits, such as hoses 41 a,b. The drive motor 102 may further includea rotor (not shown) mounted in the housing for rotation relative theretoby one or more bearings (not shown). Injection of hydraulic fluid, suchas oil, into the inlet may torsionally drive the rotor relative to thehousing 102 h. The rotor may be torsionally connected to the drive shaft102 d. The drive motor 102 may further include a motor lock operablebetween a locked position and an unlocked position. The motor lock mayinclude a clutch torsionally connecting the rotor and the housing 102 hin the locked position and disengaging the rotor from the housing in theunlocked position. The clutch may be biased toward the locked positionand further include an actuator, such as a piston, operable to move theclutch to the unlocked position in response to hydraulic fluid beingsupplied to the motor. Alternatively the motor 102 may have anadditional hydraulic port for supplying the actuator. Alternatively, themotor 102 may be electric or pneumatic.

Each tensioner 107 p may include a piston and cylinder assembly and aroller. Each piston and cylinder assembly may have a first end connectedto the respective body and a second end mounted to the roller forrotation of the roller relative thereto. Each tensioner 107 p may be influid communication with the HPU 46 via a flexible conduit, such as ahose 43 (common or individual). Each tensioner 107 p may be operated toextend the roller into engagement with the respective belt 108 d,p,thereby tightening the respective belt 108 d,p and gripper set 113 d,pinto engagement with the respective sprockets 110 p,d, 111 p,d. Eachcounter bearing 116 p may include a base connected to the respectivebody 105 d,p and one or more rollers mounted along the base for rotationrelative thereto. As each tensioner 107 p tightens the respective belt108 d,p, the belt may also be tightened into engagement with therespective counter bearing rollers, thereby supporting the belt andkeeping the belt from bowing inwardly.

Referring to FIG. 8A, alternatively, the movable segment may be mountedon a linear actuator, such as a piston and cylinder assembly, such thatthe movable segment may be radially moved toward and away from thestationary segment. This alternative facilitates adjusting of theclamping force against an outer surface of the wireline and mayaccommodate radial contraction of the wireline in response to tensionexerted on the wireline.

Alternatively, each belt may include segments spaced apart to form thecog passage instead of being continuous and the grippers may link thebelt segments. Alternatively, the cable injector 100 may be used withother types of cable, such as slickline or wire rope. Alternatively, thecable injector 100 may be configured to inject a workstring, such ascoiled tubing or continuous sucker rod.

FIGS. 4A and 4B illustrate insertion of the ESP 60 into the wellbore 5 wusing the LARS 1. FIG. 4C illustrates operation of the ESP 60. Referringspecifically to FIG. 4A, the tree valves 31, 33 may be opened. The ESP60 and running tool 59 may be assembled, lowered, and suspended in thetree 30, wellhead 10 h, and/or upper portion of the wellbore 5 w by thewinch 47. The running tool 59 may include an electrically operatedgripper for connecting to the packoff 99.

The cable injector 100 may then be connected to the BOPs 38. The cableinjector 100 may be connected with the movable segment 101 p in the openposition or without the movable segment. If connected without themovable segment 101 p, the movable segment 101 p may then be connectedto the stationary segment 101 d in the open position. The movablesegment 101 p may then be closed and secured around the wireline 50. Thehoses 41 a,b and 43 may then be connected to the cable injector 100. Thetensioners 107 p may then be operated to engage the respective belts 108d,p with the sprockets 110 d,p, 111 d,p. The winch 47 may be idled andthe drive motor 102 may then be operated to lower the ESP 60 into thewellbore 5 w using the wireline 50 until the lander 65 is proximate thedock follower 13. Should lowering of the ESP 60 become obstructed, suchas by deviations in the production tubing 10 p, the cable injector 100may push the wireline 50 into the wellbore 5 w.

Alternatively, the body 105 d may have a second coupling, such as aflange, connected at an end opposite the base such that a second cableinjector may be connected thereto and the cable injectors operated intandem.

Referring specifically to FIG. 4B, the ESP 60 may be slowly loweredwhile the follower 13 engages the cam 69 and rotates the ESP 60 relativeto the production tubing 10 p to align the wet-matable connector 16, 66.Referring specifically to FIG. 4C, lowering of the ESP 60 may continueto engage the wet-matable connector 16, 66 and to engage the packoffseal with the PBR 17. The packoff latch may be set. The running toolgripper may be operated using the wireline 50 to release the ESP 60 fromthe running tool 59. Operation of the cable injector 100 may then bereversed to retrieve the wireline 50 and running tool 59 from thewellbore 5 w. The cable injector 100, running tool 59, and BOPs 38 maybe removed from the production tree 30. The cap 34 may be connected tothe production tree 30. The SSV 3 may be opened and the ESP 60 operatedto pump production fluid 7 from the wellbore 5 w. Retrieval of the ESP60 for service or replacement may be accomplished by reversing theinsertion method.

FIG. 5A illustrates a lubricator 200 and the cable injector 100connected thereto for use with the LARS 1, according to anotherembodiment of the present disclosure. The lubricator 200 may include atool housing 205 (aka lubricator riser), a seal head 210, a tee 215, anda shutoff valve 220. The lubricator components may be connected, such asby flanged connections. The tee 215 may also have a lower flange forconnecting to the upper BOP flange. The cable injector 100 may connectto an upper flange of the seal head 210. The seal head 210 may includeone or more stuffing boxes 225 u,b and a grease injector 230. Eachstuffing box 225 u,b may include a packing, a piston, and a housing. Aport may be formed through each stuffing box housing in communicationwith the piston. The port may be connected to the HPU 46 via a hydraulicconduit (not shown). When operated by hydraulic fluid, the piston maylongitudinally compress the packing, thereby radially expanding thepacking inward into engagement with the wireline 50. Each stuffing boxmay further include a spring for returning the piston or the resiliencyof the packing may be sufficient.

The grease injector may include a housing integral with each stuffingbox housing and one or more seal tubes. Each seal tube may have an innerdiameter slightly larger than an outer diameter of the wireline 50,thereby serving as a controlled gap seal. An inlet port and an outletport may be formed through the grease injector/stuffing box housing. Agrease conduit (not shown) may connect an outlet of a grease pump (notshown) with the inlet port and another grease conduit (not shown) mayconnect the outlet port with a grease reservoir (not shown).Alternatively, the outlet port may discharge into a spent fluidcontainer. Grease 330 (FIG. 6C) may be injected from the grease pumpinto the inlet port and along the slight clearance formed between theseal tube and the wireline 50 to lubricate the wireline, reduce pressureload on the stuffing box packings, and increase service life of thestuffing box packings.

FIG. 5B illustrates an alternative PCA 240 for use with the LARS 1,according to another embodiment of the present disclosure. A moredetailed discussion regarding use of the lubricator 200 and PCA 240 maybe found in U.S. Prov. App. No. 61/550,537 (Atty. Dock. No.ZEIT/0012USL), which is herein incorporated by reference in itsentirety. The PCA 240 may include one or more clamps 241 u,b, a driver250, one or more blow out preventers (BOPs) 38, 265 and a shutoff valve262. Each PCA component may include a housing having a connector, suchas a flange, formed at each longitudinal end thereof. The flanges may beconnected by fasteners (not shown), such as bolts or studs and nuts.Each PCA housing may have a bore therethrough corresponding to a bore ofthe production tubing 10 p.

Each clamp 241 u,b may include a housing having an annular inner portionand a pair of outer portions connected to the inner portion, such as bya threaded connection or flanges. Passages may be formed through theinner portion corresponding to each outer portion. An arm may bedisposed in each outer portion. Each arm may have a piston formed at anouter end thereof and a band formed at an inner end thereof. Each bandmay be U-shaped. Each arm may be radially moveable between a disengagedposition (shown) and an engaged position (not shown). The piston maydivide each outer portion into a pair of chambers. An inner port may beformed through a wall of the inner housing portion corresponding to eachouter housing portion and an outer port may be formed through each outerportion. Each port may be connected to the HPU 46. A proximity sensor,such as a contact switch, may be connected to each arm at a base of therespective band. Leads may connect each contact switch to the PLC 42 pand may be flexible to accommodate movement of the arms. In operation,the arms may be engaged by supplying pressurized hydraulic fluid to thearm piston via outer ports and returning hydraulic fluid from the innerports, thereby moving the arms inward in opposing fashion. The arms maybe moved until the bands engage a corresponding profile, such as groove62 (FIG. 2A), formed in an outer surface of the ESP 60, therebylongitudinally connecting the ESP to the PCA 240. Engagement of thebands may be detected by operation of the contact switches. Each clamp241 u,b may be locked in the engaged position hydraulically.Disengagement of the arms may be accomplished by reversing the hydraulicflow.

The shutoff valve 262 may be manually operated. Alternatively, theshutoff valve 262 may include an actuator (not shown), such as ahydraulic actuator connected to the HPU 46 by a flexible conduit. Theannular BOP 265 may include a housing, a piston, and an annular packing.The annular BOP 265 may be the conical type (shown) or the sphericaltype (not shown). The packing, when sufficiently radially inwardlydisplaced, may sealingly engage an outer surface of the ESP 60 extendinglongitudinally through the housing.

The driver 250 may include one or more (two shown) units. The driver 250may include a housing having an annular inner portion and an outerportion for each unit connected to the inner portion, such as by athreaded connection or flanges. Passages may be formed through the innerportion corresponding to each outer portion. An arm assembly may bedisposed in each outer portion. Each arm assembly may include a pistonand a wrench connected to the piston, such as by a flanged connection.Each arm assembly may be radially moveable between a disengaged position(shown) and an engaged position. The piston may divide each outerportion into a chamber and a recess. A port may be formed through eachouter portion. Each port may be connected to the HPU 46 by an umbilical(not shown). The umbilical may include one or more conduits and/orcables, such as one or more power fluid conduits and a data cable. Thepower fluid may be hydraulic fluid and the power fluid conduits may beconnected to the HPU 46. The data cable may be connected to the PLC 42 pand may provide data communication between one or more sensors and thePLC.

Each wrench may include a motor, a reduction gear box, the sensors, anda socket. When fluid pressure is supplied to one port of the motor, theoutput shaft may rotate clockwise. This clockwise rotation of the outputshaft may be transmitted via the gears to the socket, causing the socketto rotate in the bolt tightening direction, such as in counterclockwise.Since the output shaft may rotate continuously, the socket may rotatecontinuously in the bolt tightening direction. When fluid pressure issupplied to the other port of the motor, the output shaft may rotate inthe opposite direction and thus the socket may tend to rotate in theopposite direction.

The sensors may include a video camera, a turns counter, and/or a torquesensor. The turns counter may measure an angle of rotation of thesocket. The video camera may face the socket to facilitate engagement ofthe wrench with a bolt 91 (FIG. 2D) by the control room operator. Thevideo camera may further include one or more lights. In operation, clearvisibility fluid may be pumped into the PCA bore. The arms may beengaged with respective bolts 91 by supplying pressurized hydraulicfluid to the arm pistons via ports, thereby moving the arms inward inopposing fashion. The arm assemblies may be moved synchronously orindependently by the control room operator. The control room operatormay watch video of the sockets on the display of the control console 42c to facilitate engagement of the sockets with the bolts 91. The armassemblies may be moved until the sockets engage the bolts 91. Thewrenches may be operated to tighten the bolts. Torque and turns may bemonitored to control tightening.

The driver may include a rotary table (not shown) operable to rotateeach unit relative to the inner housing portion. The inner housingportion may be modified to enclose the units. The rotary table mayinclude a stator connected to the modified inner housing portion, arotor connected to each outer housing portion, a motor for rotating therotor relative to the stator, a swivel for providing fluid and datacommunication between the wireline truck 40 and each wrench, and abearing for supporting the rotor from the stator. Alternatively, thedriver with the rotary table may only include one driver unit.

The flanged connection 90 u,b may include an upper flange 90 u connectedto the pump section housing 95 h, such as by a weld or a threadedconnection, and a lower flange 90 b connected to the pump sectionhousing 95 h, such as by a weld or a threaded connection. The flangedconnection 90 u,b, may include an auto orienting profile 92 havingmating portions formed in each flange 90 u,b. The upper flange 90 u mayhave passages formed therethrough for receiving one or more threadedfasteners, such as the bolts 91. The passage may receive a shaft of eachbolt 91 and a head of the bolt may engage an upper surface of the flange90 u when the shaft is inserted through the passage. A lower end of thesection housing 95 h may serve as a trap for the bolts 91, therebypreventing escape of the bolts 91 during insertion of the sectionhousing into the PCA 240. To trap the bolts 91, the bolts may bedisposed in the passages before the upper flange 90 u is connected tothe section housing 135 h. The lower flange 90 b may have threadedsockets 93 for receiving threaded shafts of respective bolts 91, therebyforming the flanged connection 90 u,b. The passages and sockets 93 maybe equally spaced around the respective flanges 90 u,b at apredetermined increment, such as ninety degrees for four, sixty degreesfor six, or forty-five degrees for eight.

The flanged connection 90 u,b may further include a temporary connectionfor each flange 90 u,b, such as shearable fasteners 94. One of theshearable fasteners 94 may torsionally connect the upper shaft coupling93 of the first pump section 95 to the lower flange 90 b and another oneof the shearable fasteners 94 may torsionally connect the upper shaftcoupling 93 of the second pump section 95 to the upper flange 90 u. Theshaft couplings 93 may be temporarily fastened in mating positions suchthat when the auto-orienting profile aligns the flanges 90 u,b, theshaft couplings 93 may also be aligned. The shearable fasteners 94 mayfracture in response to operation of the motor 70 once the ESP 60 haslanded in the dock 15.

To prepare for insertion, the ESP 60 may be assembled into two or moredeployment sections, such as four. The first deployment section mayinclude the motor 70 and the lander 65. The second deployment sectionmay include the shaft seal 75. The third deployment section may includethe inlet 80 and the first pump section 85. The fourth deploymentsection may include the second pump section 95 and the packoff 99. Alength of each deployment section (plus running tool 59) may be lessthan or equal to a length of the tool housing 205 h. The arrangement andnumber of deployment sections may vary based on parameters of the ESP60, such as number of stages and components.

The wireline 50 may be inserted into the seal head 210 of the lubricator200 and connected to a cablehead of the running tool 59. The runningtool 59 may then be connected to the first deployment section. The firstdeployment section may be inserted into the tool housing 205. Thelubricator 200 and first deployment section may be hoisted over the PCA240 using the wireline 50 and/or a crane (not shown).

The crane may suspend the lubricator 200 while the wireline winch 47 isoperated to lower the first deployment section until the lander 65 and alower portion of the motor 70 are accessible. The motor 70 may then beserviced, such as by adding motor oil thereto. The lubricator 200 may belowered onto the PCA 240 using the crane. The lubricator tee 215 maythen be fastened to the upper clamp 241 u, such as by a flangedconnection. The seal head 210 may be operated to engage the wireline 50.The master 31 and swab 33 valves may then be opened.

The first deployment section may be lowered into the PCA 240 using thewireline 50 until the motor groove 62 is aligned with the upper clamp241 u. The upper clamp 241 u may then be operated to engage the motor70, thereby supporting the first deployment section. The annular BOP 265may then be operated to engage the packing with an outer surface of themotor 70. Since a bottom of the motor 70 may be sealed, the firstdeployment section may plug a bore of the PCA 240, thereby sealing anupper portion of the PCA from wellbore pressure. The lubricatorconnection to the PCA 240 may be disassembled. The upper clamp 241 u mayalso secure the first deployment section from being ejected from the PCA240 due to wellbore pressure. The running tool 59 may be operated torelease the first deployment section using the wireline 50. Thelubricator 200 and running tool 59 may then be removed. The seconddeployment section may be inserted into the tool housing 205 andconnected to the running tool 59. The lubricator 200 and seconddeployment section may be hoisted over the PCA 240 using the wireline 50and/or the crane.

The crane may suspend the lubricator 200 while the wireline winch 47 isoperated to lower the second deployment section until the lower flange61 of the shaft seal 75 seats on the upper flange 61 of the motor 70.During lowering, the flanges 61 may be manually aligned and the uppermotor shaft coupling 63 may be manually aligned and engaged with thelower seal shaft coupling 63. The flanged connection 61 may beassembled. The lubricator 200 may be lowered onto the PCA 240 using thecrane 90. The lubricator tee 215 may again be fastened to the PCA 240.The seal head 210 may again be operated to engage the wireline 50. Theannular BOP 265 may be disengaged from the motor 70. The upper clamp 241u may be operated to release the motor 70. The first and seconddeployment sections may be lowered into the PCA 240 until the shaft sealgroove 62 is aligned with the upper clamp 241 u. The upper clamp 241 umay then be operated to engage the shaft seal 75, thereby supporting thefirst and second deployment sections. The annular BOP 265 may then beoperated to engage an outer surface of the shaft seal 75.

The lubricator connection to the PCA 240 may be disassembled. Therunning tool 59 may be operated to release the second deployment sectionusing the wireline 50. The lubricator 200 and running tool 59 may thenbe removed. The third deployment section may be inserted into the toolhousing 205 and connected to the running tool 59. The lubricator 200 andthird deployment section may be hoisted over the PCA 240 using thewireline 80 and/or the crane. The crane may suspend the lubricator 200while the wireline winch 47 is operated to lower the third deploymentsection until the lower first pump section flange 61 seats on the uppershaft seal flange 61. During lowering, the flanges 61 may be manuallyaligned and the upper seal shaft coupling 63 may be manually aligned andengaged with the lower pump section shaft coupling 63. The flangedconnection 101 may be assembled. The lubricator 200 may be lowered ontothe PCA 240 using the crane 90. The lubricator tee 215 may again befastened to the PCA 240. The seal head 210 may again be operated toengage the wireline 50. The annular BOP 265 may be disengaged from theshaft seal 75. The upper clamp 241 u may be operated to release theshaft seal 75. The first, second, and third deployment sections may belowered into the PCA 240 until the first pump section groove 62 isaligned with the lower clamp 241 b. The lower clamp 241 b may then beoperated to engage the first pump section 85, thereby supporting thedeployment sections.

Since the third and fourth deployment sections may have openthrough-bores, the open deployment sections may not be used as plugs andthe isolation valve 262 may be used to close the upper portion of thePCA. The running tool 59 may be operated to release the third deploymentsection using the wireline 50. The running tool 59 may be raised fromthe PCA 240 into the lubricator 200 using the wireline 50. The isolationvalve 262 may be closed. The lubricator connection to the PCA 240 may bedisassembled. The lubricator 200 and running tool 59 may then beremoved. The fourth deployment section may be inserted into the toolhousing 205 and connected to the running tool. The lubricator 200 andfourth deployment section may be hoisted over the PCA 240 using thewireline 50 and/or the crane.

The lubricator 200 may be lowered onto the PCA 240 using the crane. Thelubricator tee 215 may again be fastened to the PCA 240. The seal head210 may again be operated to engage the wireline 50. The isolation valve262 may be opened. Visibility fluid may be injected into the PCA 240.The running tool 59 and fourth deployment section may be lowered intothe PCA 240 until the upper first pump section flange 90 u is proximateto the lower second pump section flange 90 b. The fourth deploymentsection may be slowly lowered to engage the parts of the auto-orientingprofile 92 for aligning the flanges 90 u,b. Once the auto-orientingprofile 92 has mated, the driver arm assemblies 53 may be operated toengage the bolts 91.

Each driver motor may be operated to rotate the bolts 91 into respectivesockets 93. Torque and turns may be monitored by the control roomoperator and/or the PLC 42 p to ensure proper assembly. The armassemblies 53 may be disengaged from the upper flange 130 u. Once theflanged connection 90 ub, has been fully assembled, the lower clamp 241b may be operated to disengage the first pump section housing 95 h. Thecable injector 100 may then be connected to a top of the lubricator 200and closed/assembled around the wireline 50. The cable injector 100 maythen be operated to lower the assembled ESP 60 into the wellbore 5 w.

Alternatively, the tool housing 205 may have a length corresponding to alength of the ESP 60, thereby obviating the need for the PCA 240.

FIG. 6A illustrates a power cable deployed ESP 360 for use with amodified LARS. The modified LARS may be similar to the LARS 1 exceptthat the LARS truck components may be mounted on a skid frame and thepower converter 45 may output a medium voltage DC power signal to thewireline for driving the ESP 360. The medium voltage power signal may begreater than or equal to one kilovolt, such as three to ten kilovolts.The LARS PLC 42 p may further include a data modem and a multiplexer formodulating and multiplexing a data signal to/from the downholecontroller with the DC power signal.

The ESP 360 may include the electric motor 70, a power conversion module(PCM) 361, the seal section 75, the inlet 80, the pump 85, a lander 363,an outlet 364, and a cablehead 365. Additionally, the pump 85 may be afirst pump section and the ESP 360 may further include the second pumpsection (see pump section 95). Housings of each of the ESP componentsmay be longitudinally and torsionally connected, such as by flanged orthreaded connections. The cablehead 365 may include a cable fastener(not shown), such as slips or a clamp for longitudinally connecting theESP 360 to the wireline 50.

The wireline 50 may be longitudinally coupled to the cablehead 365 by ashearable connection (not shown). The wireline 50 may be sufficientlystrong so that a margin exists between the deployment weight and thestrength thereof. The cablehead 365 may further include a fishneck sothat if the ESP 360 become trapped in the wellbore 5 w, such as bybuildup of sand, the wireline 50 may be freed from rest of thecomponents by operating the shearable connection and a fishing tool (notshown), may be deployed to retrieve the ESP 360.

The cablehead 365 may also include leads extending therethrough. Theleads may provide electrical communication between the conductors of thewireline 50 and the PCM 361. The PCM 361 may include a power supply, amotor controller (not shown), a modem (not shown), and multiplexer (notshown). The motor controller may be similar to the motor controller ofthe control unit 39. The power supply may include one or more DC/DCconverters, each converter including an inverter, a transformer, and arectifier for converting the DC power signal into an AC power signal andreducing the voltage from medium to low. Each converter may be a singlephase active bridge circuit as discussed and illustrated in PCTPublication WO 2008/148613, which is herein incorporated by reference inits entirety. The power supply may include multiple DC/DC converters inseries to gradually reduce the DC voltage from medium to low. For theSRM and BLDC motors, the low voltage DC signal may then be supplied tothe motor controller. For the induction motor, the power supply mayfurther include a three-phase inverter for receiving the low voltage DCpower signal from the DC/DC converters and outputting a three phase lowvoltage AC power signal to the motor controller.

The PCM modem and multiplexer may demultiplex a data signal from the DCpower signal, demodulate the signal, and transmit the data signal to themotor controller. The motor controller may be in data communication withone or more sensors (not shown) distributed throughout the ESP 360. Apressure and temperature (PT) sensor may be in fluid communication withthe reservoir fluid 7 entering the inlet 80. A gas to oil ratio (GOR)sensor may also be in fluid communication with the reservoir fluid 7entering the inlet 80. A second PT sensor may be in fluid communicationwith the reservoir fluid 35 discharged from the outlet 364. Atemperature sensor (or PT sensor) may be in fluid communication with thelubricant to ensure that the motor 70 and PCM 361 are being sufficientlycooled. Multiple temperature sensors may also be included in the PCM 361for monitoring and recording temperatures of the various electroniccomponents. A voltage meter and current (VAMP) sensor may be inelectrical communication with the wireline 50 to monitor power losstherefrom. A second VAMP sensor may be in electrical communication withthe power supply output to monitor performance of the power supply.Further, one or more vibration sensors may monitor operation of themotor 70, the pump 85, and/or the seal section 75. A flow meter may bein fluid communication with the outlet 364 for monitoring a flow rate ofthe pump 85. Utilizing data from the sensors, the motor controller maymonitor for adverse conditions, such as pump-off, gas lock, or abnormalpower performance and take remedial action before damage to the pump 85and/or motor 70 occurs.

In anticipation of depletion, the production tubing string 310 p mayhave a landing nipple 315 installed at a lower end thereof. The landingnipple 315 may have a seal bore, a torsional coupling, such as anauto-orienting castellation, and a stop shoulder. The lander 363 mayhave a tubing seal, a torsional coupling, such as an auto-orientingcastellation, and a stop shoulder. Engagement of the lander 363 with thelanding nipple 315 may engage the tubing seal with the seal bore, alignthe castellations, and engage the stop shoulders, thereby longitudinallysupporting the ESP 360 from the production tubing string 310 p andtorsionally connecting the ESP to the production tubing string, andisolating the inlet 64 i from the outlet 640.

Alternatively, the ESP 360 may include an isolation device having ananchor and a packer instead of the lander 363.

FIG. 6B illustrates insertion of the ESP 360 into the wellbore 5 w usingthe cable injector 100, according to another embodiment of the presentdisclosure. FIG. 6C illustrates operation of the power cable deployedESP 360. Referring specifically to FIG. 6B, the tree valves 31, 33 maybe opened. The ESP 360, running tool 59 and seal head 210 may beassembled, the seal head 210 may be connected to the tree 30, and theESP and running tool may be lowered and suspended in the tree 30,wellhead 10 h, and/or upper portion of the wellbore 5 w by the winch 47.The cable injector 100 may then be connected to a top of the seal head210 and closed/assembled around the wireline 50. The cable injector 100may then be operated to lower the ESP 360 into the wellbore 5 w usingthe wireline 50 until the motor 70 is adjacent to the SSV 3.

Referring specifically to FIG. 6C, the seal head 210 may then beoperated to engage the wireline 50 and the SSV 3 opened. The cableinjector 100 may then continue to lower the ESP 360 to the deploymentdepth. Once the lander 363 has engaged the landing nipple 315, the cableinjector 100 may be disassembled and disconnected from the seal head210. The ESP 360 may then be operated to pump production fluid 7 fromthe wellbore 5 w.

Alternatively, the seal head may be operated to engage the wirelinebefore lowering the ESP 360 into the wellbore. Alternatively, the restof the lubricator 200 may be used to assemble, insert, and/or deploy theESP 360, as discussed above for the ESP 60.

FIGS. 7A-7D illustrate insertion of the power cable deployed ESP 360into the wellbore 5 w using the cable injector 100, according to anotherembodiment of the present disclosure. FIG. 7E illustrates operation ofthe power cable deployed ESP 360. Referring specifically to FIG. 7A, thetree valves 31, 33 may be opened. The ESP 360, running tool 59 and one225 u of the stuffing boxes 225 u,b may be assembled, the stuffing box225 u may be connected to the tree 30, and the ESP and running tool maybe suspended in the tree 30 and/or upper portion of the wellbore 5 w bythe winch 47. The cable injector 100 may then be connected to a top ofthe stuffing box 225 u and closed/assembled around the wireline 50. Thecable injector 100 may then be operated to lower the ESP 360 into thewellbore 5 w using the wireline 50 until the motor 70 is adjacent to theSSV 3 and/or the deployment depth.

Referring specifically to FIG. 7B, the winch 47 may then be locked tosuspend the ESP 360. The cable injector 100 may be disassembled anddisconnected from the seal head 210. A mold 301 may be assembled aroundthe wireline 50 and connected to a top of the stuffing box 225 u. A moredetailed discussion regarding use of the mold 301 may be found in U.S.patent application Ser. No. 13/447,001 (Atty. Dock. No. ZEIT/0006US),which is herein incorporated by reference in its entirety.

The mold 301 may be delivered to the wellsite by a service truck (notshown). The service truck may include a reaction injector and a crane orplatform to lift the mold to a top of the stuffing box. The reactioninjector may include a pair of supply tanks each having a liquidreactive component (aka resin and hardener) stored therein. The supplytanks or the components may or may not be heated. The service truck mayfurther include a pair of feed pumps, each having an inlet connected toa respective supply tank. An outlet of each supply pump may be connectedto a mix head and an outlet of the mix head may connect to the mold 301.The service truck may further include an HPU for powering the supplypumps. The service truck may further include a controller forproportioning the feed pumps. The feed pumps may be operated tosimultaneously supply the liquid reactive components to the mix head.The mix head may impinge the liquid components to begin polymerizationof the sealant mixture 345. The sealant mixture 345 may continue fromthe mix head into the mold 301.

The mold 301 may include a split housing 305 and upper and lower seals(not shown). The housing 305 may include a pair of mating semi-tubularsegments 305 a,b. Each housing segment 305 a,b may have radialcouplings, such as flanges 308, formed therealong and half of alongitudinal coupling (not shown), such as a flange, formed at one orboth longitudinal ends thereof. The radial flanges 308 of each housingsegment 305 a,b may be connected to the mating radial flanges byfasteners 307, such as bolts and nuts. A gasket 309 may be disposed in agroove formed in one of the housing segments for sealing the radialconnection. Each seal may include a pair of mating semi-annularsegments.

An inner diameter of the mold housing 305 may be slightly greater thanan outer diameter of the wireline 50, thereby forming an annulus 312between the mold housing and the wireline. The housing 305 may have asprue 306 formed through a wall of one of the segments 305 a,b and influid communication with the annulus 312. An inner diameter of the moldseals may be slightly less than an outer diameter of the wireline 50 sothat the mold seals engage an outer surface of the wireline the mold 301is assembled.

Referring specifically to FIG. 7C, the sealant 345 may be a polymer,such as an elastomer or thermoplastic elastomer. Once the mold 301 hasbeen assembled around the wireline 50, the mix head may be lifted to themold 301 by the service truck crane or the service truck platform maylift the reaction injector to the mold 301. The mix head may beconnected to the sprue 306. The supply pumps may then be operated topump the liquid reactants to the mix head. The sealant mixture 345 maycontinue from the mix head into the mold 301. Air displaced by thesealant mixture 345 may vent from the mold via leakage through and alongthe armor 57 i,o. The sealant mixture 345 may flow around and along theannulus 312 until the sealant mixture 345 encounters the seals. Pressurein the mold 301 may increase and the sealant mixture 345 may be forcedinto the armor 57 i,o. Sealant penetration into the wireline 50 may bestopped by the outer jacket 56. Pumping of the sealant mixture 345 maycontinue until the mold 301 is filled. The mold 301 may be heated byexothermic polymerization of the mixture 345. A melting temperature ofthe mold seals, gasket 309, and outer jacket 56 may be suitable towithstand the exothermic reaction.

Referring specifically to FIG. 7D, once the sealant 345 has cured andcooled to at least a point sufficient to maintain structural integrity,the mix head may be disconnected from the mold 301 and the mold 301 maybe disconnected from the stuffing box 225 u. The fasteners 307 may thenbe removed. The service truck may further include a hydraulic spreader.The spreader may be connected to the mold 301 and operated to separatethe mold. The service truck may stow the mold 301 and mix head and leavethe wellsite. A length of the sealed portion 350 may correspond to alength of a seal of the stuffing box 225 u and be substantially lessthan a length of the wireline 50. An outer diameter of the sealedportion 350 may be slightly greater than an outer diameter of the restof the wireline 50.

Referring specifically to FIG. 7D, the stuffing box 225 u may then beoperated to engage the wireline 50 and the SSV 3 opened. The winch 47may then be unlocked and operated to lower the ESP 360 to deploymentdepth. Alternatively, the cable injector 100 may be reinstalled aroundthe sealed portion 350 and operated to lower the ESP 360 to deploymentdepth. As the ESP 360 is lowered, the sealed portion 350 may be loweredinto alignment with the stuffing box seal as the lander 363 engages withthe landing nipple 315. The ESP 360 may then be operated to pumpproduction fluid 7 from the wellbore 5 w.

While the foregoing is directed to embodiments of the presentdisclosure, other and further embodiments of the disclosure may bedevised without departing from the basic scope thereof, and the scope ofthe invention is determined by the claims that follow.

1. An injector for deploying a cable into a wellbore, comprising: atraction assembly comprising at least a stationary segment and a movablesegment, each segment comprising: a drive sprocket; an idler sprocket; atrack looped around and between the sprockets; a set of grippersfastened to and disposed along the respective track, a frame: connectedto the stationary segment, having a coupling for connection to apressure control assembly (PCA), and having a passage for receiving thecable; and a motor torsionally connected to the drive sprocket of thestationary segment.
 2. The injector of claim 1, wherein each gripper hasan opening for receiving a cog of the respective sprockets.
 3. Theinjector of claim 2, wherein each track is a belt having a passageadjacent each gripper for passing the cog.
 4. The injector of claim 1,wherein each gripper: is made from a metal, alloy, or cermet, has arecess formed therein for receiving the cable, and has teeth formed inthe recess.
 5. The injector of claim 4, wherein each gripper has wingsextending transversely from the recess.
 6. The injector of claim 1,wherein the movable segment is pivoted to the stationary segment forswinging between an open position for receiving the cable and a closedposition for deploying the cable.
 7. The injector of claim 6, wherein:each segment further comprises a gear torsionally connected to therespective drive sprocket, and the gears mesh upon closing of themovable segment.
 8. The injector of claim 6, wherein each segmentfurther comprises a body having a hinge knuckle formed at each inner endthereof.
 9. The injector of claim 1, wherein each segment furthercomprises: a tensioner operable to tighten the respective track, and acounter bearing for supporting the tightened track.
 10. The injector ofclaim 1, wherein the traction assembly further comprises a secondmovable segment.
 11. The injector of claim 1, further comprising alinear actuator operable to move the movable segment toward and awayfrom the stationary segment.
 12. A launch and recovery system (LARS),comprising: the injector of claim 1; a winch having the cable; a boomfor guiding the cable into the PCA; the PCA for connection to aproduction tree; and a downhole assembly of an artificial lift systemfor deployment into the wellbore using the cable.
 13. The LARS of claim12, further comprising a stuffing box having a coupling for connectionto the PCA and a coupling for connection to the injector.
 14. The LARSof claim 13, further comprising a seal head having the stuffing box anda grease injector.
 15. The LARS of claim 14, further comprising alubricator having the seal head and a tool housing.
 16. A method ofdeploying a downhole tool into a wellbore, comprising: connecting thedownhole tool to a cable; lowering the downhole tool into a pressurecontrol assembly (PCA) and wellhead adjacent to the wellbore using thecable; after lowering the downhole tool, connecting a cable injector tothe PCA and closing the cable injector around the cable; and operatingthe cable injector, thereby injecting the cable into the wellbore andlowering the downhole tool to a deployment depth in the wellbore. 17.The method of claim 16, wherein the downhole tool is lowered by:assembling the PCA onto a production tree connected to the wellhead;inserting a first deployment section of the downhole tool into alubricator; landing the lubricator onto the PCA; connecting thelubricator to the PCA; lowering the first deployment section into thePCA; engaging a clamp of the PCA with the first deployment section;after engaging the clamp, isolating an upper portion of the PCA from alower portion of the PCA by engaging a seal of the PCA with the firstdeployment section; and after isolating the PCA, removing the lubricatorfrom the PCA.
 18. The method of claim 16, further comprising connectinga stuffing box to the PCA, wherein the cable injector is connected tothe PCA by being connected to the stuffing box.
 19. The method of claim18, further comprising: engaging a mold with an outer surface of thecable; injecting sealant into the mold and into armor of the cable,thereby sealing a portion of the cable; engaging a seal of the stuffingbox with the sealed portion of the cable; and operating the downholetool using the cable.
 20. The method of claim 18, wherein: the stuffingbox is part of a seal head having a grease injector, and the methodfurther comprises: engaging the seal head with the cable; and operatingthe downhole tool using the cable.
 21. The method of claim 16, wherein:the downhole tool is an electrical submersible pump (ESP), and themethod further comprises operating the ESP to pump production fluid fromthe wellbore.
 22. The method of claim 21, wherein the ESP is operated byreceiving a power signal from the cable.
 23. The method of claim 21,wherein: the ESP lands into a dock of production tubing at thedeployment depth, and the ESP is operated by receiving a power signalfrom the dock.
 24. The method of claim 23, wherein: the PCA is mountedon a production tree connected to the wellhead, the method furthercomprises: disconnecting the cable from the ESP; retrieving the cablefrom the wellbore; and removing the PCA and cable injector from theproduction tree.
 25. The method of claim 16, wherein the cable iscoaxial wireline.